6. Assignment of Proceeding
Michael R. Peevey is the assigned Commissioner and Thomas R. Pulsifer is the assigned ALJ.
1. PG&E entered into a series of settlements, covering the scope of Phase 2 issues as set forth in the appendices of this decision. Each of the settlements had support among all active parties relating to each referenced subject area, except for certain objections relating to solar rate incentives, and agricultural pumping rates.
2. Although the Master Meter Schedule ET discount was not resolved by settlement, the only parties submitting responsive testimony to PG&E's proposed Schedule ET discount were The Utility Reform Network and WMA.
3. Evidentiary hearings were held to address and resolve disputed issues relating to the Schedule ET Discount for master meter MHP customers.
4. California's strong public policy is to favor settlements, thereby supporting many worthwhile goals, such as reducing litigation expense, conserving scarce resources, and reducing parties' risk that litigation will produce unacceptable results.
5. The Commission considers individual settlement provisions but, in light of California's strong public policy in favor of settlements, does not base its conclusion primarily on whether any single provision is the necessarily optimal result but rather on whether the settlement as a whole produces a just and reasonable outcome.
6. Except for the limited protests noted below, each of the Settlements are sponsored by all active parties participating in each respective subject area, including residential, small commercial, large commercial, agricultural and industrial customers. As such each of the settlements is fairly reflective of the affected interests.
7. The Settlements, along with the full evidentiary record, contain sufficient information for the Commission to discharge its future regulatory duties with respect to adopted matters.
8. The settlements submitted on marginal cost and revenue allocation, streetlight rate designed, and SLP rate design are uncontested all-party settlements.
9. The relative percentage increases and decreases in average electric rates for customer classes as set forth in Appendix A of this decision, under the column entitled "Settlement", represents the applicable changes that result from the Settlement Agreement on Revenue Allocation and Marginal Cost. The revenue allocation percentages shown in Appendix G result from the adopted settlement agreements.
10. The MLLP settlement is supported by all active parties, with the exception of elements contested by certain parties regarding the treatment of (a) customer eligibility for the Schedule A-6 Solar Pilot and (b) the Option R rate schedule allowing reduced demand charges for solar customers.
11. The MLLP settlement is reasonable in light of the whole record, after taking into consideration disposition of the contested issues raised by Solar Alliance to expand the A-6 Solar Pilot and to introduce an Option R rate.
12. Under the existing Schedule A-6 Solar Pilot, customers otherwise required to take service under Schedule E-19 (i.e., customers with ordinary demands above 500 kW) are allowed to take service on Schedule A-6 if they serve at least 20 % of their maximum demand with solar DG.
13. The proposal to increase the eligibility for the A-6 Solar Pilot by raising the cap on participation from 20 MW to 50 MW would result in increased subsidies, and would increase the degree of cost shifting to non-participating customers.
14. The E-19 and E-20 schedules include time-differentiated demand charges in on-peak and partial peak periods for both generation and distribution costs. All distribution costs, except those paid in a fixed customer charge, are capacity-related, and cannot be avoided by reducing energy consumption during a peak hour.
15. Capacity-related costs occur at the distribution, transmission and generation levels of the electric grid.
16. Because generation, transmission and primary distribution infrastructure serve many customers, an individual customer's contribution to these capacity costs depends on the customer's contribution to the coincident peak at the corresponding level of aggregation.
17. For the portion of the distribution system that is closest to the customer, the capacity required to serve the customer is driven by the customer's non-coincident peak demand. Because the distribution capacity costs for infrastructure near the customer are a function of the customer's maximum demand, non-coincident demand charges are an appropriate mechanism for collecting the revenues needed to cover these costs.
18. Because an individual customer's peak load may not coincide with system peak loads, demand charges, even peak-period demand charges, to collect revenues for generation, transmission and primary distribution capacity costs only approximate customers' contributions to system peaks.
19. Customers' average demands during peak hours may better reflect their contribution to upstream capacity costs. Thus, the use of TOU energy charges to spread these costs over all peak hours during a billing period may yield more accurately capacity charges for upstream capacity costs rather than instantaneous peak-period and non-coincident maximum demand charges, particularly for customers with erratic loads, such as customers with behind-the-meter solar generation facilities.
20. The demand charge rate structure proposed in the MLLP settlement is consistent with long-established rate design principles for large customers
21. Solar Alliance's proposed rate options to expand the A-6 Pilot and to introduce an Option R rate are designed to reduce or eliminate the use of demand charges, and instead collect larger portions of costs in more readily avoidable energy (per kWh) charges. An additional number of customers with very large electric loads would receive service under a tariff originally designed to meet the needs of much smaller commercial customers (i.e., with demands of 20-50 kW.
22. Shifting demand charges to TOU energy rates increases the rate at which net energy metered customers are compensated for net exports during discrete TOU periods. To the extent higher compensation rates for net energy metering exports may overcompensate customer-generators for their solar energy, an increased cross-subsidy from noncustomer-generators may occur.
23. It is not clear whether Public Utilities Code Section 2827(h)(2)(B) would allow an electric utility to offer an optional rate for customer-generators that would compensate customer-generators at a lower rate during a discrete TOU period than they would otherwise pay for energy consumed during that TOU period.
24. Under the Electric MHP Service ET rate schedule, electricity is delivered to a single master meter and then delivered to end users at individual mobile homes through a sub metered private distribution system
25. The ET discount compensates the master metered MHP owner for those costs that the utility avoids because the master metered MHP owner has submetered all the tenants' spaces rather than have the utility directly serve them.
26. In calculating the ET discount, PG&E proposed escalation factors to adjust its new connection equipment costs from 2003 to 2011 dollars using labor (O&M) escalation specific to PG&E. All parties agreed with this approach.
27. All parties agree to use ML&P (Schedule A-10) connection costs at secondary voltage as a reasonable proxy for the MHP master meter connection costs.
28. The quantified effect on the ET discount is small, with PG&E's proposed after-tax RECC adjustment lowering its recalculated ET discount by less than a penny per space per day (all else equal) relative to TURN's previously proposed pre-tax RECC adjustment.
29. The addition of an EPMC scalar in calculating the Schedule ET discount would artificially inflate the discount by overstating utility avoided costs, and would contravene established Commission precedent.
30. The inclusion of connection costs above the utility line extension allowance in the Schedule ET discount would contravene D.04-04-043 Attachment A.
31. WMA's proposal to add explicit replacement costs in the Schedule ET discount would causes double counting.
32. The use of residential class average equipment costs to calculate the Schedule ET discount would produce inflated results because it is predominantly based on single family units which have higher costs of service than do both multifamily and MHPs costs.
33. The agricultural rate design settlement was contested only with respect to the opposing proposal of Lamont Public Utility District in seeking to expand the applicability of Schedule E-37 to include non-agricultural pumping customers.
34. Although Lamont presented limited cost data comparisons, there is no actual cost of service study in the record applicable to high-load factor non-agricultural pumping account customers. Lamont's comparison metrics are anecdotal, and are not an acceptable substitute for a marginal cost of service study.
35. A cost of service study would be necessary as an initial step to determine the cost to serve the high-load factor non-agricultural pumping account customers in addition to the current E-37 rate class.
36. Without a cost of service study, Lamont's proposal for expanded eligibility for the E-37 rate schedule could lead to significant cost shifts to other groups of customers without cost-based justification.
37. The Commission adopts revenue allocation based on broad customer classes or subclasses that generally reflect average costs of service for each class, with rates set accordingly.
38. As a basis for assessing the merits of expanding the Schedule E-37 eligibility, all of the factors affecting the cost basis of rates are relevant, not just the load factor. Other key factors include size of customers, location of customers, voltage levels of customers, and summer/winter splits of usage.
39. There is no evidence that the load shapes of high load factor non-agricultural pumping account customers or their seasonal usage is similar to those of current E-37 customers. There is no evidence comparing their contributions to system peak or maximum demand to those of all current E-37 customers.
40. Although customers with more usage during the winter compared to the summer are less expensive to serve on a cost per kWh basis, the customers Lamont proposes to add to the schedule are served at lower voltages.
41. PG&E's tariffs maintain stability among rate group definitions in a mutually exclusive manner and do not allow customers to migrate between customer classes (absent specific legislative or Commission direction.)
42. Schedule AG-5B and E-37 rates currently are identical and based on the merged billing determinants and cost of service determination of both.
43. The 2014 GRC will provide an opportunity to develop an adequate record regarding a cost of service study of both oil pumping customers and non-agricultural pumping customers, and to devote more careful consideration to the rate impacts of merging the billing determinants and costs of service of different groups of customers.
44. The settlement agreements on marginal cost and revenue allocation, streetlight rate design, SLP rate design, MLLP rate design, and agricultural rate design settlement agreements are each reasonable in light of the record, consistent with law and in the public interest.
1. The Commission will not approve a settlement unless it is reasonable in light of the whole record, consistent with law, and in the public interest.
2. The Commission will not approve an all-party settlement unless the settlement commands the unanimous sponsorship of all active parties, sponsoring parties are fairly reflective of the affected interests, no settlement term contravenes statutory provisions or prior Commission decisions, and the settlement conveys sufficient information to permit the Commission to discharge future regulatory obligations with respect to parties and their interests.
3. The all-party settlements submitted in this proceeding, covering revenue allocation and marginal cost, SLP rate design, streetlight rate design, and Schedule ES and Natural Gas Baseline Quantities satisfy the Commission's criteria for reasonableness and should be approved. Each of the pending motions to approve these settlements should be granted.
4. Although the MLLP rate design settlement was contested by certain parties with respect to proposals to expand eligibility for the A-6 Solar Pilot and introduce an Option R provision, the settlement was otherwise supported by all active parties in all other respects, and nonetheless is reasonable in light of the whole record and warrants approval and adoption. The motion to approve the MLLP rate design settlement should be granted.
5. The proposal to expand eligibility for the A-6 Solar Pilot and introduce an Option R provision should be denied. Instead, the proposals in the MLLP Settlement Agreement pertaining to the A-6 Solar Pilot and Option R should be adopted.
6. Prior to filing its next GRC Phase 2 application, PG&E should complete a cost study on the extent to which the demand charges in the E-19 and E-20 tariffs penalize customers with erratic loads by overcharging them for their contributions to systems peaks. This cost study should evaluate:
(a) whether an Option R rate for E-19 and E-20 customers that shifts some portion of generation and distribution demand charges to TOU energy charges may more appropriately recover capacity-related costs from customers with on-site solar generation facilities;
(b) the correlation of solar output and solar customer-generator loads at various levels of geographic aggregation and how the correlation, or lack of correlation, affects their contribution to capacity costs;
(c) the additional compensation that may accrue to customer-generators as a result of higher TOU energy rates under net energy metering; whether the higher compensation results in an additional subsidy for customer-generators; and
(d) the feasibility of designing optional rates that offer different rates for energy consumption and net energy production during discrete TOU periods.
7. Although the Agricultural Rate Design Settlement was contested with respect to the proposal to expand the eligibility of Schedule E-37 to include certain non-agricultural pumping customers, the settlement was otherwise supported by all active parties in all other respects, and nonetheless is reasonable in light of the whole record and should be approved and adopted. The motion to approve the Agricultural Rate Design Settlement should be granted.
8. The proposal of the Lamont Public Utility District to expand eligibility for Schedule E-37 to include non-agricultural general water or sewage pumping customers whose annual metered usage is 70% or more for and whose annual load factor is 50% or more should be denied. Lamont describes these customers as High-load factor Non-Agricultural Pumping accounts.
9. The proposal of the Lamont Public Utility District to permit high-load factor non-agricultural pumping accounts to migrate from the existing applicable General Service tariff to some other rate schedule with rates comparable to E-37 should be denied.
10. The proposals in the Agricultural Settlement with respect to Schedule E-37 are reasonable and should be adopted without change.
11. The proposed Schedule ET master meter discount of $6.53 per master meter MHP space per month, $1.02 Line Loss Adder, and the illustrative Diversity Benefit Adjustment of $5.15, all proposed by PG&E and supported by TURN, are reasonable and should be adopted for purposes of this proceeding.
12. PG&E's illustrative Diversity Benefit Adjustment of $5.15 should be adopted subject to recalculation after the adoption of this decision.
13. PG&E's proposed weighted after-tax cost of debt Real Economic Carrying Charge adjustment should be used for the limited purpose of setting the ET discount in this proceeding, without setting a precedent for purposes of any other proceedings.
14. WMA's claim that the Commission must decide whether connection costs above the utility line extension allowance are in or out of the submeter discount, as this would contravene D.04-04- 043 Attachment A.
15. In order to provide a more informed basis for future determinations of master meter discounts, Pacific Gas and Electric should be required to collect information on the actual costs of serving mobile home park customers and present this data in its next Phase 2 GRC proceeding.
16. This order should be made effective immediately so that PG&E may prepare the necessary advice letter, and so that rates may be timely adjusted
IT IS ORDERED that:
1. The motions, filed by Pacific Gas and Electric Company, and which request adoption of each of the settlement agreements, as referenced below respectively, are each hereby granted. Each of the settlement agreements attached to the motions respectively, are identified below:
Date of Motion |
Scope of Settlement Agreement |
a. March 14, 2011 |
Marginal Cost and Revenue Allocation |
b. April 8, 2011 |
Medium and Large Light and Power (MLLP) Rate Design |
c. April 8, 2011 (As amended September 22, 2011) |
Small Light and Power (SLP Rate Design |
d. June 3, 2011 |
Streetlighting Rate Design |
e. June 22, 2011 |
Schedule ES and Natural Gas Baseline Quantities |
f. July 18, 2011 |
Agricultural Rate Design |
2. The terms of each of the settlement agreements as referenced in Ordering Paragraph 1, and as reproduced in Appendices A, B, C, D, E and F of this decision, respectively, are hereby approved and adopted without change.
3. Pacific Gas and Electric Company is directed to file tariffs within 15 days of the date this decision is mailed, in compliance with General Order 96-B, to implement the revenue allocations and rate design changes for the respective customer classes identified in the adopted settlement agreements in accordance with the terms and conditions as set forth in Appendices A, B, C, D, E and F, and as adopted herein.
4. Pacific Gas and Electric Company's revised tariff sheets to implement the revenue allocations and rate designs adopted in this order shall become effective on or after January 1, 2012, subject to Energy Division determining that they are in compliance with this order. No additional customer notice need be provided pursuant to General Rule 4.2 of General Order 96-B for this advice letter filing.
5. The rules governing the existing revenue requirement categories presented in the March 14, 2011, Settlement Agreement are adopted for use in this proceeding only, and shall not govern or be precedential for purposes of Pacific Gas and Electric Company's 2014 General Rate Case.
6. Pacific Gas and Electric Company shall schedule and conduct workshops, providing notice to parties in this proceeding prior to filing its 2014 general rate case Phase 2 application. The workshops shall be a forum to discuss the data and/or methodologies that might be used in that proceeding, and potential model simplification and transparency, for: (a) the marginal generation cost data that might be used to develop marginal costs; (b) the marginal distribution capacity costs and marginal customer access cost data to develop marginal costs; and (c) revenue allocation methodologies that might be used to develop positions in the 2014 general rate case Phase 2.
7. The proposal of The Solar Alliance is requesting to expand the eligibility of the Schedule A-6 Pilot from the existing cap of 20 megawatt (MW) to 50 MW denied.
8. The proposal of The Solar Alliance requesting to implement an Option R under Schedules E-10 and E-20 to replace the otherwise-applicable generation capacity-based time-of-use (TOU) demand charges with energy charges, and replace 50 percent of the standard non-TOU distribution-related maximum demand charges with non-TOU energy charges is denied.
9. Prior to filing its next General Rate Case Phase 2 application, Pacific Gas and Electric Company shall complete a cost study on the extent to which the demand charges in the E-19 and E-20 tariffs penalize customers with erratic loads by overcharging them for their contributions to systems peaks. The cost study shall include the following analysis:
a. Evaluation of whether an Option R rate for E-19 and E-20 customers that shifts some portion of generation and distribution demand charges to time-of-use energy charges may more appropriately recover capacity-related costs from customers with on-site solar generation facilities.
b. Assessment of data on the correlation of solar output and solar customer-generator loads at various levels of geographic aggregation and how the correlation, or lack of correlation, affects their contribution to capacity costs.
c. Estimation of the additional compensation that may accrue to customer-generators as a result of higher time-of-use energy rates under net energy metering,
d. Discussion of whether the higher rates of net energy metering compensation result in additional subsidy for customer-generators, and discussion of the feasibility of designing optional rates that offer different rates for energy consumption and net energy production during discrete time-of-use periods.
10. The proposal of Lamont Public Utility District is to expand the eligibility of Agricultural Rate Schedule E-37 (or another comparable rate schedule) to include non-agricultural general water or sewage pumping customers whose annual metered usage is 70% or more for and whose annual load factor is 50% or more, described as High-load factor Non-Agricultural Pumping accounts hereby denied.
11. The Pacific Gas and Electric Company's proposal for the Schedule ET avoided cost-based base discount of $6.53 per master meter mobile home park space per month is hereby adopted.
12. Pacific Gas and Electric Company's proposed $1.02 Line Loss Adder is adopted.
13. Pacific Gas and Electric Company's illustrative Diversity Benefit Adjustment of $5.15 is approved, subject to recalculation after the adoption of this decision.
14. Pacific Gas and Electric Company's proposed escalation factors applicable to ET discount cost inputs are hereby adopted.
15. Pacific Gas and Electric Company's proposed transformer costs, at secondary voltage, for calculating the Mobile Home Park master meter connections are hereby adopted.
16. Pacific Gas and Electric Company's weighted after-tax cost of debt Real Economic Carrying Charge adjustment is adopted for the sole purpose of setting the ET discount in this proceeding, without setting a precedent for purposes of other proceedings,
17. Pacific Gas and Electric Company's adjustments to Account 903 costs are adopted, which exclude from the Schedule ET discount specific ongoing utility costs in Account 903 that are still incurred despite Pacific Gas and Electric Company not having to directly serve each Mobile Home Park tenant.
18. Pacific Gas and Electric Company's proposed Minimum Average Rate Limiter is adopted.
19. Pacific Gas and Electric Company and The Utility Reform Network's proposed use of marginal customer access Costs is hereby approved to develop the Schedule ET discount using the Commission-approved rental cost method.
20. Pacific Gas and Electric Company and The Utility Reform Network's proposed use of 2003 General Rate Case access equipment cost data, escalated to 2011, is hereby approved for Schedule ET rate design.
21. Pacific Gas and Electric Company and The Utility Reform Network's proposed use of multifamily service line connection costs is hereby approved for Schedule ET discount calculations.
22. Pacific Gas and Electric Company's transformer costs, at secondary voltage, for Mobile Home Park master meter connections are adopted for purposes of the Schedule ET discount calculations.
23. Prior to its filing its next General Rate Case Phase 2 application, Pacific Gas and Electric Company shall collect data and complete a study on the actual costs to serve mobile home park customers as a basis to better determine the costs that the utility would have incurred in providing comparable services directly to the users of the service.
24. This proceeding remains open to consider Phase III issues as previously identified by the Assigned Commissioners' Scoping Memo.
25. Application 10-03-014 remains open.
This order is effective today.
Dated , at San Francisco, California.
